Hydrocarbon feedstocks such as petroleum crudes, gas oil, etc., are subjected to various processes in order to isolate and separate different fractions of the feed stock. In refinery processes, the feedstock is distilled so as to provide light hydrocarbons, gasoline, naphtha, kerosene, gas oil, etc.
The lower, boiling fractions are recovered as an overhead fraction from the distillation tower. The intermediate components are recovered as side cuts from the distillation tower. The fractions are cooled, condensed, and sent to collecting equipment. No matter what type of petroleum feed stock is used as the charge, the distillation equipment is subjected to the corrosive activity of acids such as H2S, HCl, organic acids, and H2CO3.
Corrosion in the crude overhead distillation equipment is mainly due to condensation of hydrogen chlorides formed by hydrolysis of the magnesium chloride and calcium chloride in crude oil. Typical hydrolysis reactions may proceed as in Equations I or II:MgCl2+2H2O2HCl+Mg(OH)2  (I)CaCl2+2H2O2HCl+Ca(OH)2  (II)
Corrosive attack on the metals normally used in the low temperature sections of a refinery (i.e., where water is present below its dew point) is an electrochemical reaction generally in the form of acid attack on active metals in accordance with Equations III, IV or V:At the anode: FeFe+++2e−  (III)At the cathode: 2H++2e−2H  (IV)At the cathode: 2HH2  (V)
The aqueous phase may be water entrained in the hydrocarbons being processed and/or water added to the process for such purposes as steam stripping. These waters, regardless of source, are collectively referred to as brines. Acidity of the condensed water is due to dissolved acids in the condensate, principally HCl, organic acids, H2S, and H2CO3. HCl, the most troublesome corrosive material, is formed by hydrolysis of calcium and magnesium chlorides originally present in the brines.
One of the chief points of difficulty with respect to corrosion occurs above and in the temperature range of the initial condensation of water. The term “initial condensate” as it is used herein signifies a phase formed when the temperature of the surrounding environments reaches the dew point of water. At this point a mixture of liquid water, hydrocarbon, and vapor may be present. Such initial condensate may occur within the distillation tower itself or in subsequent condensers. The top temperature of the distillation tower is normally maintained above the dew point of water. The initial aqueous condensate formed contains a high percentage of HCl. Due to the high concentration of acids dissolved in the water, the pH of the first condensate is quite low. For this reason, the water is highly corrosive.
In the past, highly basic ammonia has been added at various points in hydrocarbon refining processes in an attempt to control the corrosiveness of condensed acidic materials Ammonia, however, has not proven effective with respect to eliminating corrosion occurring at the initial condensate. It is believed that ammonia has been ineffective for this purpose because it does not condense completely enough to neutralize the acidic components of the first condensate.
Several amines, including morpholine and methoxypropylamine, have been used to successfully control or inhibit corrosion that ordinarily occurs at the point of initial condensation within or after the distillation tower. These amines or their blends are added in pure form or as an aqueous solution. The high alkalinity of these amines serves to raise the pH of the initial condensate rendering it less corrosive. The amines are added in amounts sufficient to raise the pH of the liquid at the point of initial condensation to above 4.0, and in some cases, to between 5.0 and 6.0.
These amines, however, form hydrochloride salts that deposit on the inner surfaces of hydrocarbon refining equipment. These deposits can cause both fouling and corrosion problems and are most problematic in units that do not use a water wash.
Some amines and their blends currently used produce less salt deposits on hydrocarbon refining equipment than the amines listed above. These amines are also aqueous amines and are introduced in the distillation tower or downstream of the distillation tower. These amines include picoline (U.S. Pat. No. 5,211,840) and blends comprising dimethylethanolamine and dimethylisopropanolamine, (U.S. Pat. No. 4,490,275) ethylenediamine, monoethanolamine and hexylmethylenediamine (U.S. Pat. No. 7,381,319). Additional amines include trimethylamine and N-methylmorpholine and their blends.